Solvent-dominated in situ oil recovery processes are those in which chemical solvents are used to reduce the viscosity of the in situ oil. A minority of commercial viscous oil recovery processes use solvents to reduce viscosity. Most commercial recovery schemes rely on thermal methods such as Cyclic Steam Stimulation (CSS, see, for example, U.S. Pat. No. 4,280,559) and Steam-Assisted Gravity Drainage (SAGD, see, for example U.S. Pat. No. 4,344,485) to reduce the viscosity of the in situ oil. As thermal recovery technology has matured, practitioners have added chemical solvents, typically hydrocarbons, to the injected steam in order to obtain additional viscosity reduction. Examples include Liquid Addition to Steam For Enhancing Recovery (LASER, see, for example, U.S. Pat. No. 6,708,759) and Steam And Vapor Extraction processes (SAVEX, see, for example, U.S. Pat. No. 6,662,872). These processes use chemical solvents as an additive within an injection stream that is steam-dominated. Solvent-dominated recovery processes are a possible next step for viscous oil recovery technology. In these envisioned processes, chemical solvent is the principal component within the injected stream. Some non-commercial technology, such as Vapor Extraction (VAPEX, see, for example, R. M. Butler & I. J. Mokrys, J. of Canadian Petroleum Technology, Vol. 30, pp. 97-106, 1991) and Cyclic Solvent-Dominated Recovery Process (CSDRP, see, for example, Canadian Patent No. 2,349,234) use injectants that may be 100%, or nearly all, chemical solvent.
At the present time, solvent-dominated recovery processes (SDRPs) are rarely used to produce highly viscous oil. Highly viscous oils are produced primarily using thermal methods in which heat, typically in the form of steam, is added to the reservoir. Cyclic solvent-dominated recovery processes (CSDRPs) are a subset of SDRPs. A CSDRP is typically, but not necessarily, a non-thermal recovery method that uses a solvent to mobilize viscous oil by cycles of injection and production. Solvent-dominated means that the injectant comprises greater than 50% by mass of solvent or that greater than 50% of the produced oil's viscosity reduction is obtained by chemical solvation rather than by thermal means. One possible laboratory method for roughly comparing the relative contribution of heat and dilution to the viscosity reduction obtained in a proposed oil recovery process is to compare the viscosity obtained by diluting an oil sample with a solvent to the viscosity reduction obtained by heating the sample.
Although preferably a CSDRP is predominantly a non-thermal process in that heat is not used principally to reduce the viscosity of the viscous oil, the use of heat is not excluded. Heating may be beneficial to improve performance, improve process start-up, or provide flow assurance during production. For start-up, low-level heating (for example, less than 100° C.) may be appropriate. Low-level heating of the solvent prior to injection may also be performed to provide general flow assurance such as preventing hydrate formation in tubulars and in the reservoir. Heating to higher temperatures may benefit recovery.
In a CSDRP, a viscosity-reducing solvent is injected through a well into a subterranean viscous-oil reservoir, causing the pressure to increase. Next, the pressure is lowered and reduced-viscosity oil is produced to the surface through the same well through which the solvent was injected. Multiple cycles of injection and production are used. In some instances, a well may not undergo cycles of injection and production, but only cycles of injection or only cycles of production.
CSDRPs may be particularly attractive for thinner or lower-oil-saturation reservoirs. In such reservoirs, thermal methods utilizing heat to reduce viscous oil viscosity may be inefficient due to excessive heat loss to the overburden and/or underburden and/or reservoir with low oil content.
References describing specific CSDRPs include: Canadian Patent No. 2,349,234 (Lim et al.); G. B. Lim et al., “Three-dimensional Scaled Physical Modeling of Solvent Vapour Extraction of Cold Lake Bitumen”, The Journal of Canadian Petroleum Technology, 35(4), pp. 32-40, April 1996; G. B. Lim et al., “Cyclic Stimulation of Cold Lake Oil Sand with Supercritical Ethane”, SPE Paper 30298, 1995; U.S. Pat. No. 3,954,141 (Allen et al.); and M. Feali et al., “Feasibility Study of the Cyclic VAPEX Process for Low Permeable Carbonate Systems”, International Petroleum Technology Conference Paper 12833, 2008.
The family of processes within the Lim et al. references describes embodiments of a particular SDRP that is also a cyclic solvent-dominated recovery process (CSDRP). These processes relate to the recovery of heavy oil and bitumen from subterranean reservoirs using cyclic injection of a solvent in the liquid state which vaporizes upon production. The family of processes within the Lim et al. references may be referred to as CSP™ technology.
In order to handle the host of challenges for a solvent-dominated injection operation, a methodology is needed to manage overall solvent injection, production, supply, and reuse. This challenge becomes increasingly complex as additional wells or pads are brought online. Optimally, the methodology should account for the fact that the scheduling of each well depends on the previous injection and production histories of the well, the injection and production rates of every other well in the field, the supply of solvent to the field, the value of each stream of components being injected and produced from that well, and the properties of the reservoir near the well and near the volume of the reservoir previously accessed by solvent.
Descriptions of solvent-dominated cyclic recovery processes (such as in Canadian Patent No. 2,349,234) refer to the general operation of a well for a solvent-dominated cyclic recovery process.
Other examples of cyclic oil recovery processes also exist, such as cyclic steam stimulation (e.g., U.S. Pat. No. 3,739,852) and cyclic steam injection (e.g., U.S. Pat. No. 3,434,544), but the value of the produced injectant (water in these cases) is less than the value of solvent, and thus, careful management of the produced injectant is not as important. Moreover, water can be stored as a liquid at atmospheric conditions, and therefore there is less incentive to minimize surface solvent storage.
The following additional references are mentioned but also do not describe a method of distributing a viscosity reducing solvent to an underground oil reservoir to minimize the net rate of solvent injection in order to minimize solvent storage.
United States Patent Publication No. 2008/0294484 describes an optimization system for transportation scheduling and inventory management of a bulk product from supply locations to demand locations.
U.S. Pat. No. 7,289,942 and International Patent Application No. WO 2006/044199A2 describe computer-implemented methods of analyzing performance of a hydrocarbon reservoir for the prediction of future production of hydrocarbon fluids from wells in the reservoir.
International Patent Application No. WO 2009/061433 describes a computer modeling application for finding the optimal solution to maximize total net margin, for the assignment of vehicles in an available fleet to transport cargo comprising one or more bulk products during a planning period.
U.S. Pat. No. 7,418,307 and United States Patent Publication No. 2008/0275796 describe methods for managing a component supply for the assembly of complex products.
U.S. Pat. No. 3,954,141 describes using a solvent which is gaseous at formation temperature and pressure or using a solvent being selected from the group consisting of paraffinic hydrocarbons having at least six carbon atoms, mono-nuclear aromatic hydrocarbons, naphtha, natural gasoline and mixtures thereof.
U.S. Pat. No. 7,546,228 teaches a computer-implemented method comprising the computer instantiating a first set of one or more random variables that model one or more uncertain time durations associated with one or more respective processes occurring in a first schedule, to determine one or more first instantiated values.
U.S. Pat. No. 7,478,024 describes a method of managing a fluid or gas reservoir that assimilates diverse data having different acquisition time scales and spatial scales of coverage for iteratively producing a reservoir development plan that is used for optimizing an overall performance of a reservoir.
There remains a need for reducing pipeline capacity, surface solvent storage, or underground solvent storage costs in solvent-dominated processes for recovering in situ hydrocarbons.